US7740062B2 - System and method for the recovery of hydrocarbons by in-situ combustion - Google Patents
System and method for the recovery of hydrocarbons by in-situ combustion Download PDFInfo
- Publication number
- US7740062B2 US7740062B2 US12/022,310 US2231008A US7740062B2 US 7740062 B2 US7740062 B2 US 7740062B2 US 2231008 A US2231008 A US 2231008A US 7740062 B2 US7740062 B2 US 7740062B2
- Authority
- US
- United States
- Prior art keywords
- production
- offset
- reservoir
- primary
- plane
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active, expires
Links
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/243—Combustion in situ
Definitions
- a system and a method for recovering hydrocarbons from a reservoir containing hydrocarbons by in-situ combustion are disclosed.
- ISC In-situ combustion
- SAGD steam assisted gravity drainage
- ISC processes include those disclosed in: “Experimental and Numerical Simulations of a Novel Top Down In-Situ Combustion Process”, Coates, R., Lorimer, S., Ivory, J., Society of Petroleum Engineers, SPE 30295, 1995; U.S. Pat. No. 5,211,230 (Ostapovich et al); U.S. Pat. No. 5,456,315 (Kisman et al); U.S. Pat. No. 5,626,191 (Greaves et al); U.S. Pat. No. 6,167,966 (Ayasse et al); U.S. Pat. No. 6,412,557 (Ayasse et al); PCT International Publication No.
- the present invention is a system and a method for recovering hydrocarbons from a reservoir containing hydrocarbons.
- the invention utilizes in-situ combustion (ISC).
- the system of the invention is comprised of a primary liquid production wellbore, at least one vent well and an injector apparatus, all of which are associated with a reservoir containing hydrocarbons.
- the primary liquid production wellbore has a substantially horizontal primary production length which extends through the reservoir.
- the vent well is in fluid communication with the reservoir at a venting position in the reservoir.
- the injector apparatus is in fluid communication with the reservoir along an injection line in the reservoir.
- the venting position is relatively higher in the reservoir than the primary production length.
- the injection line is relatively higher in the reservoir than the primary production length, and the injection line is relatively lower in the reservoir than the venting position.
- the invention may be a system for recovering a hydrocarbon liquid from a subterranean reservoir containing hydrocarbons, the system comprising:
- the injection line may be comprised of a continuous line of injection or may be comprised of a plurality of discrete points of injection which together provide the injection line.
- the injection line may be laterally offset from the primary production plane.
- the injection line may be positioned substantially within the primary production plane, such that the injection line is substantially above the primary production length.
- the injector apparatus may be comprised of one or more injection wellbores, so that the one or more injection wellbores provide the injection line.
- the injector apparatus may be comprised of an injection wellbore having a substantially horizontal injection length, and the injection line may be comprised of the injection length of the injection wellbore.
- the injector apparatus may be comprised of a plurality of injection wellbores, and each of the injection wellbores may be in fluid communication with the reservoir along the injection line in order to provide the injection line.
- the injector apparatus may be comprised of a row of substantially vertical injection wellbores, wherein each of the injection wellbores is in fluid communication with the reservoir along the injection line in order to provide the injection line.
- the at least one vent well facilitates venting from the reservoir of gases contained in the reservoir.
- gases contained in the reservoir may be comprised of gases produced from the combustion of hydrocarbons in the reservoir, unreacted injection gas and natural gas.
- the venting position may be positioned substantially within the primary production plane. Alternatively, the venting position may be laterally offset from the primary production plane.
- the at least one vent well may be comprised of a single vent well or a plurality of vent wells.
- the venting position may be comprised of a plurality of venting positions which are provided by a plurality of vent wells. Where the venting position is comprised of a plurality of venting positions, one or more of the venting positions may be located at different positions relative to the primary production plane.
- the vent wells may be comprised of vertical wells, directional wells, and/or may include substantially horizontal lengths which extend through the reservoir.
- each of the venting positions may be laterally offset from the primary production plane.
- at least one of the venting positions may be laterally offset from the primary production plane on a first side of the primary production plane and at least one of the venting positions may be laterally offset from the primary production plane on a second side of the primary production plane.
- at least one of the venting positions may be laterally offset from the primary production plane by a first venting distance on a first side of the primary production plane and at least one of the venting positions may be laterally offset from the primary production plane by a second venting distance on the first side of the primary production plane, wherein the second venting distance is greater than the first venting distance.
- one or more venting positions may be laterally offset from the primary production plane on different sides of the primary production plane and/or by different distances from the primary production plane.
- the system may be further comprised of one or more offset liquid production wellbores, each having a substantially horizontal offset production length which extends through the reservoir, wherein the offset production length is laterally offset from the primary production plane.
- the injection line is preferably relatively higher in the reservoir than the offset production lengths.
- the offset production lengths may be oriented in any direction relative to the primary production plane.
- an offset production length may be oriented perpendicular to the primary production plane, oblique to the primary production plane, or parallel to the primary production plane.
- the offset production lengths may be laterally offset from the primary production plane on the same side of the primary production plane or on different sides of the primary production plane.
- the offset production lengths may be laterally offset from the primary production plane by the same distance or by different distances from the primary production plane.
- offset production lengths may be laterally offset from the primary production plane on different sides of the primary production plane.
- offset production lengths may be laterally offset from the primary production plane by different distances on the same side of the primary production plane.
- offset production lengths may be laterally offset from the primary production plane on different sides of the primary production plane and by different distances from the primary production plane.
- the system may be comprised of a first offset liquid production wellbore having a first offset production length which is laterally offset from the primary production plane by a first production distance on a first side of the primary production plane.
- the system may be comprised of a second offset liquid production wellbore having a second offset production length which is laterally offset from the primary production plane by a second production distance on the first side of the primary production plane, wherein the second production distance is greater than the first production distance.
- the system may be comprised of a third offset liquid production wellbore having a third offset production length which is laterally offset from the primary production plane by a third production distance on a second side of the primary production plane.
- the system may be comprised of a fourth offset liquid production wellbore having a fourth offset production length which is laterally offset from the primary production plane by a fourth production distance on the second side of the primary production plane, wherein the fourth production distance is greater than the third production distance.
- the first offset liquid production wellbore and/or the third offset liquid production wellbore may comprise a first set of offset liquid production wellbores, and the third production distance may be substantially equal to the first production distance.
- the second offset liquid production wellbore and/or the fourth offset liquid production wellbore may comprise a second set of offset liquid production wellbores, and the fourth production distance may be substantially equal to the second production distance.
- venting positions are dependent upon the overall configuration of the system and upon other factors, including the number and configuration of the offset liquid production wellbores.
- the injection gas source may be comprised of any source of an injection gas containing oxygen which is suitable for injection into the reservoir in order to cause combustion of the hydrocarbons contained in the reservoir.
- the injection gas source may be comprised of a source of air, oxygen enriched air or some other oxygen containing gas.
- the injection gas source may be further comprised of a compressor, pump or other apparatus for delivering the injection gas to the injection line and the reservoir.
- the invention may be a method for recovering a hydrocarbon liquid from a subterranean reservoir containing hydrocarbons, the method comprising:
- the method may be further comprised of pre-treating the reservoir before injecting the injection gas into the reservoir, in order to enhance the injectivity of the injection gas into the reservoir, in order to mobilize the hydrocarbons located adjacent to the injection line and the primary production length, in order to heat the hydrocarbons to facilitate combustion, or for some other purpose.
- exemplary pre-treatments may be comprised of thermal pre-treatment by the introduction of heat into the reservoir, physical pre-treatment by diluting or dissolving the hydrocarbons contained in the reservoir, chemical pre-treatment by altering the chemical composition of the hydrocarbons contained in the reservoir.
- pre-treatment of the reservoir may be comprised of a thermal pre-treatment, a physical pre-treatment, or a combination of a thermal pre-treatment and a physical pre-treatment.
- the method may be further comprised of injecting steam into the reservoir along the injection line for a steam injection period, before injecting the injection gas into the reservoir along the injection line.
- the method may be further comprised of electrically heating the reservoir, injecting a solvent into the reservoir, or injecting a combination of steam and a solvent into the reservoir.
- the method may be further comprised of providing one or more offset liquid production wellbores, each having a substantially horizontal offset production length which extends through the reservoir, wherein the offset production lengths are laterally offset from the primary production plane, and the method may be further comprised of producing the hydrocarbon liquid from the offset liquid production wellbores.
- the offset production lengths may be laterally offset from the primary production plane on the same side or on different sides of the primary production plane and/or may be laterally offset from the primary production plane by the same distance or by different distances from the primary production plane. Any number of offset liquid production wellbores may be provided in the invention.
- the method may be further comprised of ceasing producing the hydrocarbon liquid from the primary liquid production wellbore upon detection of a threshold amount of a breakthrough gas at the primary liquid production wellbore.
- the threshold amount of the breakthrough gas may be any amount which is considered to be tolerable in the performance of the method, and may be represented by direct and/or indirect detection and/or measurement of the injection gas, its constituents or its products of combustion.
- the method may be further comprised of providing a first offset liquid production wellbore having a substantially horizontal first offset production length which extends through the reservoir, wherein the first offset production length is laterally offset from the primary production plane by a first production distance on a first side of the primary production plane, and the method may be further comprised of producing the hydrocarbon liquid from the first offset liquid production wellbore.
- the method may be further comprised of providing a second offset liquid production wellbore having a substantially horizontal second offset production length which extends through the reservoir, wherein the second offset production length is laterally offset from the primary production plane by a second production distance on the first side of the primary production plane, and the method may be further comprised of producing the hydrocarbon liquid from the second offset liquid production wellbore.
- the method may be further comprised of providing offset liquid production wellbores in addition to the first offset liquid production wellbore and the second offset liquid production wellbore.
- a substantially symmetrical configuration of wellbores may be provided in which offset production lengths are laterally offset from the primary production plane on both sides of the primary production plane and in which the offset production lengths on both sides of the primary production plane are laterally offset from the primary production plane by substantially similar distances.
- the first offset production length and the second offset production length may be provided on the first side of the primary production plane, and a third offset production length and/or a fourth offset production length may be provided on a second side of the primary production plane.
- the first offset liquid production wellbore and the third offset liquid production wellbore may comprise a first set of offset liquid production wellbores
- the second offset liquid production wellbore and the fourth offset liquid production wellbore may comprise a second set of offset liquid production wellbores.
- the method of the invention may be performed in a staged manner in which the production of the hydrocarbon liquid begins along the primary production plane and moves away from the primary production plane as the combustion of the hydrocarbons in the reservoir progresses.
- the method of the invention may be performed in a substantially symmetrical staged manner by producing the hydrocarbon liquid on both sides of the primary production plane or in a non-symmetrical manner by producing the hydrocarbon liquid on a single side of the primary production plane.
- the injection gas may be injected into the reservoir along the injection line and the hydrocarbon liquid may be produced from the primary liquid production wellbore (i.e., along the primary production plane).
- Gases contained in the reservoir (such as, for example, gases produced from the combustion of the hydrocarbons, unreacted injection gas and/or natural gas) may be vented from one or more venting positions which are substantially within the primary production plane or laterally offset from the primary production plane by relatively small distances.
- the injection gas may be injected into the reservoir along the injection line and the hydrocarbon liquid may be produced from the primary liquid production wellbore and from a first set of offset liquid production wellbores.
- the first set of offset liquid production wellbores may comprise a single offset liquid production wellbore having an offset production length which is laterally offset from the primary production plane by a relatively small distance on one side of the primary production plane (for a non-symmetrical configuration) or may comprise a pair of offset liquid production wellbores having offset production lengths which are each laterally offset from the primary production plane by a relatively small distance on both sides of the primary production plane (for a symmetrical configuration).
- Gases contained in the reservoir may be vented from the same venting positions used in the first stage, and/or from other venting positions which are laterally offset from the primary production plane by a greater distance than those used in the first stage. Some gases may also be vented from the first set of offset liquid production wellbores.
- production of the hydrocarbon liquid from the primary liquid production wellbore may cease upon detection of a threshold amount of a breakthrough gas at the primary liquid production wellbore.
- the injection gas may be injected into the reservoir along the injection line and the hydrocarbon liquid may be produced from the first set of offset liquid production wellbores and from a second set of offset liquid production wellbores.
- the second set of offset liquid production wellbores may comprise a single offset liquid production wellbore having an offset production length which is laterally offset from the primary production plane by a greater distance than the first set of offset liquid production wellbores on one side of the primary production plane (for a non-symmetrical configuration) or may comprise a pair of offset liquid production wellbores having offset production lengths which are each laterally offset from the primary production plane by a greater distance than the first set of offset liquid production wellbores on both sides of the primary production plane (for a symmetrical configuration).
- Gases contained in the reservoir may be vented from the same venting positions used in the second stage, and/or from other venting positions which are laterally offset from the primary production plane by a greater distance than those used in the second stage. Some gases may also be vented from the sets of offset liquid production wellbores.
- production of the hydrocarbon liquid from the first set of offset liquid production wellbores may cease upon detection of a threshold amount of a breakthrough gas at the first set of offset liquid production wellbores.
- the injection gas may be injected into the reservoir along the offset production lengths of the first set of offset liquid production wellbores in order to enhance the delivery of the injection gas toward the second set of offset liquid production wellbores.
- the injection of the injection gas along the injection line may cease or may continue.
- some or all of the gases which are vented from the venting positions may be injected into the reservoir along the injection line and/or along the primary production length in order to sequester the gases and/or increase or maintain the reservoir pressure.
- production of the hydrocarbon liquid may be commenced from additional sets of offset liquid production wellbores having offset production lengths which are laterally offset from the primary production plane by increasing distances (on one side of the primary production plane or on both sides of the primary production plane), and gases may be vented from venting positions which are laterally offset from the primary production plane by increasing distances.
- these sets of offset liquid production wellbores may be used for injection of the injection gas and may subsequently be used for injection of gases which are vented from the venting positions.
- one or more offset injector apparatus may be provided which are laterally offset from the primary production plane and which are associated with one or more of the sets of offset liquid production wellbores.
- Such offset injector apparatus may be configured in a similar manner as the injector apparatus which is associated with the primary liquid production wellbore.
- the use of offset injector apparatus may be beneficial for ameliorating uneven production of the hydrocarbon liquid amongst and along the liquid production wellbores.
- an offset injector apparatus is provided, it is preferably configured so that it provides an injection line or injection point which is relatively higher in the reservoir than the adjacent production lengths and which is relatively lower in the reservoir than the adjacent venting positions.
- FIG. 1 is a schematic cross-section view of a system for recovering a hydrocarbon liquid from a reservoir according to one embodiment of the invention which includes a symmetrical configuration of offset liquid production wellbores.
- FIG. 2 is a graph depicting gas production rate and oxygen concentration in produced gas from a primary liquid production wellbore, for a three-dimensional laboratory test (Test 2) of the method of the invention.
- FIG. 3 is a graph depicting gas production rate and oxygen concentration in produced gas from a vent well, for a three-dimensional laboratory test (Test 2) of the method of the invention.
- FIG. 4 is a graph depicting injection gas volumes, gas production volumes, and oxygen utilization, for a three-dimensional laboratory test (Test 2) of the method of the invention.
- FIG. 5 is a graph depicting estimated oil production rates and recovery factors, for a three-dimensional laboratory test (Test 2) of the method of the invention.
- FIG. 6 is a graph depicting cumulative injected oxygen to oil produced ratio (OOR) and cumulative volume of injected gas, for a three-dimensional laboratory test (Test 2) of the method of the invention.
- FIG. 7 is a depiction of a non-symmetrical numerical model used in a CMG STARSTM simulation of the method of the invention.
- FIG. 8 is a graph comparing the instantaneous oil production rates from a CMG STARSTM simulation of a staged application of the method of the invention and of a staged steam assisted gravity drainage (SAGD) process using a similar system configuration.
- SAGD staged steam assisted gravity drainage
- FIG. 9 is a graph comparing the calendar day oil production rates from a CMG STARSTM simulation of a staged application of the method of the invention and of a staged steam assisted gravity drainage (SAGD) process using a similar system configuration.
- SAGD staged steam assisted gravity drainage
- FIG. 10 is a graph comparing the hydrocarbon recovery factors from a CMG STARSTM simulation of a staged application of the method of the invention and of a staged steam assisted gravity drainage (SAGD) process using a similar system configuration.
- SAGD staged steam assisted gravity drainage
- FIG. 11 is a graph comparing the oxygen to produced hydrocarbon (oil) ratio from a CMG STARSTM simulation of a staged application of the method of the invention and of a staged steam assisted gravity drainage (SAGD) process using a similar system configuration.
- SAGD staged steam assisted gravity drainage
- FIG. 12 is a graph depicting temperature distribution throughout the non-symmetrical numerical model of FIG. 2 on day 3519 from a CMG STARSTM simulation of a staged application of the method of the invention.
- FIG. 13 is a graph depicting hydrocarbon (oil) saturation throughout the non-symmetrical numerical model of FIG. 2 on day 3519 from a CMG STARSTM simulation of a staged application of the method of the invention.
- the present invention is a system and a method for recovering hydrocarbons from a reservoir containing hydrocarbons by in-situ combustion (ISC).
- ISC in-situ combustion
- the system may be configured, and the method may be performed in a single stage or in a plurality of stages.
- the system may be configured, and the method may be performed, in a substantially symmetrical manner or in a non-symmetrical manner relative to the primary production plane, depending upon a configuration of offset liquid production wellbores.
- FIG. 1 there is depicted a schematic cross-section view of a system ( 20 ) according to one embodiment of the invention which includes a symmetrical configuration of offset liquid production wellbores which may be used in a staged performance of the method of the invention.
- the system ( 20 ) is installed in a subterranean environment.
- the subterranean environment includes a subterranean reservoir ( 22 ) containing hydrocarbons.
- An overburden ( 24 ) is located above the reservoir ( 22 ).
- An underburden (not shown) is located below the reservoir ( 22 ).
- a primary liquid production wellbore ( 26 ) penetrates the reservoir ( 22 ).
- the primary liquid production wellbore ( 26 ) has a substantially horizontal primary production length ( 28 ) which extends through the reservoir ( 22 ).
- the primary production length ( 28 ) is positioned substantially within a vertical primary production plane ( 30 ).
- a plurality of vent wells ( 32 ) are in fluid communication with the reservoir ( 22 ) at venting positions ( 34 ) in the reservoir ( 22 ).
- the venting positions ( 34 ) are relatively higher in the reservoir ( 22 ) than the primary production length ( 28 ).
- venting positions ( 34 ) are laterally offset from the primary production plane ( 30 ) on opposite sides of the primary production plane ( 30 ) and at varying venting distances ( 35 ) from the primary production plane ( 30 ), but are arranged generally symmetrically relative to the primary production plane ( 30 ).
- the vent wells ( 32 ) may be vertical wells. Alternatively, the vent wells ( 32 ) may be directional wells and/or may include substantially horizontal lengths which extend through the reservoir ( 22 ), thereby increasing the venting area provided by the vent wells ( 32 ).
- An injector apparatus ( 36 ) is in fluid communication with the reservoir ( 22 ) along an injection line ( 38 ) in the reservoir ( 22 ).
- the injection line ( 38 ) is a line in the reservoir ( 22 ) along which injection of an injection gas takes place.
- the injection line ( 38 ) is substantially parallel with the primary production plane ( 30 ). As depicted in FIG. 1 , the injection line is directly above the primary production length ( 28 ), and is therefore positioned substantially within the primary production plane ( 30 ).
- the injection line ( 38 ) is provided and/or defined by one or more injection wellbores ( 40 ).
- the injection line ( 38 ) may be provided by a substantially horizontal injection length of a single injection wellbore ( 40 ), or the injection line ( 38 ) may be provided by a plurality of injection wellbores ( 40 ), such as a row of vertical wellbores with discrete injection points at their distal ends which together provide the injection line ( 38 ).
- the injection line ( 38 ) extends along at least a portion of the primary production length ( 28 ). Preferably the injection line ( 38 ) extends along substantially the entire primary production length ( 28 ).
- the injection line ( 38 ) is relatively higher in the reservoir ( 22 ) than the primary production length ( 28 ), and is relatively lower in the reservoir ( 22 ) than the venting positions ( 34 ).
- An injection gas source ( 41 ) is connected with the injector apparatus ( 36 ).
- the injection gas source ( 41 ) supplies an injection gas (not shown) containing oxygen to the injector apparatus ( 36 ) for injecting along the injection line ( 38 ) in order to cause combustion of the hydrocarbons contained in the reservoir ( 22 ).
- the injection gas source ( 41 ) may be comprised of a source of air, oxygen enriched air, or some other oxygen containing gas.
- the injection gas source ( 41 ) may be further comprised of a compressor, a pump, or some other apparatus for delivering the injection gas to the injection line ( 38 ) and the reservoir ( 22 ).
- the system ( 20 ) may be further comprised of an igniter (not shown) for initiating combustion of the hydrocarbons contained in the reservoir ( 22 ) in the presence of the injection gas.
- a first offset liquid production wellbore ( 42 ) has a first offset production length ( 44 ) which extends through the reservoir ( 22 ).
- the first offset production length ( 44 ) is laterally offset from the primary production plane ( 30 ) by a first production distance ( 46 ) on a first side ( 48 ) of the primary production plane ( 30 ).
- a second offset liquid production wellbore ( 50 ) has a second offset production length ( 52 ) which extends through the reservoir ( 22 ).
- the second offset production length ( 52 ) is laterally offset from the primary production plane ( 30 ) by a second production distance ( 54 ) on the first side ( 48 ) of the primary production plane ( 30 ).
- a third offset liquid production wellbore ( 56 ) has a third offset production length ( 58 ) which extends through the reservoir ( 22 ).
- the third offset production length ( 58 ) is laterally offset from the primary production plane ( 30 ) by a third production distance ( 60 ) on a second side ( 62 ) of the primary production plane ( 30 ).
- a fourth offset liquid production wellbore ( 64 ) has a fourth offset production length ( 66 ) which extends through the reservoir ( 22 ).
- the fourth offset production length ( 66 ) is laterally offset from the primary production plane ( 30 ) by a fourth production distance ( 68 ) on the second side ( 62 ) of the primary production plane ( 30 ).
- the second production distance ( 54 ) is greater than the first production distance ( 46 ).
- the fourth production distance ( 68 ) is greater than the third production distance ( 60 ).
- the first offset liquid production wellbore ( 42 ) and the third offset liquid production wellbore ( 56 ) comprise a first set of offset liquid production wellbores.
- the second offset liquid production wellbore ( 50 ) and the fourth offset liquid production wellbore ( 64 ) comprise a second set of offset liquid production wellbores.
- the first production distance ( 46 ) and the third production distance ( 60 ) are substantially equal, and the second production distance ( 54 ) and the fourth production distance ( 68 ) are substantially equal, with the result that the configuration of the system ( 20 ), including the offset production lengths ( 44 , 52 , 58 , 66 ), is substantially symmetrical.
- the injection line ( 38 ) is relatively higher in the reservoir ( 22 ) than the offset production lengths ( 44 , 52 , 58 , 66 ). As depicted in FIG. 1 , the offset production lengths ( 44 , 52 , 58 , 66 ) are substantially parallel with the primary production plane ( 30 ) and are at substantially the same level in the reservoir ( 30 ) as the primary production length ( 28 ).
- venting distances ( 35 ) for the venting positions ( 34 ) substantially correspond with the production distances ( 46 , 54 , 60 , 68 ).
- the first production distance ( 46 ) and the third production distance ( 60 ) may each be about fifty (50) meters
- the second production distance ( 54 ) and the fourth production distance ( 68 ) may each be about one hundred (100) meters.
- venting positions ( 34 ) may coincide with the production distances ( 46 , 54 , 60 , 68 ) so that the venting distances are about fifty (50) meters and about one hundred (100) meters.
- the method of the invention may be performed using the system ( 20 ) of the invention, or may be performed using some other system which is suitable for performing the method of the invention.
- the method is performed using a system ( 20 ) substantially as depicted in FIG. 1 and substantially as described above.
- the method of the invention is comprised of injecting an injection gas containing oxygen into the reservoir ( 22 ) along the injection line ( 38 ) in order to cause combustion of the hydrocarbons contained in the reservoir ( 22 ), thereby heating the reservoir ( 22 ) so that hydrocarbon liquid (not shown) drains toward the primary liquid production wellbore ( 26 ).
- the method of the invention further comprises producing the hydrocarbon liquid from the primary liquid production wellbore ( 26 ) and venting from the vent wells ( 32 ), gases produced from the combustion of the hydrocarbons.
- the method may be preceded by or may be further comprised of pre-treating the reservoir ( 22 ) before injecting the injection gas into the reservoir ( 22 ).
- the pre-treating may be performed in order to enhance the injectivity of the injection gas into the reservoir ( 22 ), in order to mobilize the hydrocarbons located adjacent to the injection line ( 38 ) and the primary production length ( 28 ), in order to heat the hydrocarbons to facilitate combustion, or for some other purpose directed at conditioning the reservoir ( 22 ) for performance of the method.
- the method of the invention is preceded by or is further comprised of pre-treating the reservoir ( 22 ) by injecting steam into the reservoir ( 22 ) along the injection line ( 38 ) for a steam injection period, before injecting the injection gas into the reservoir ( 22 ).
- the steam injection may be continued until fluid communication between the injection line ( 38 ) and the primary production length ( 28 ) is established and/or until a small steam chamber is formed above the injection line ( 38 ).
- This pre-treating of the reservoir ( 22 ) helps to minimize countercurrent flows between the injection gas and the heated hydrocarbon liquid, and helps to minimize combustion of hydrocarbons in the immediate vicinity of the injection line ( 38 ) and the primary production length ( 28 ).
- a first stage of the method may be initiated by commencing injection of the injection gas into the reservoir ( 22 ).
- an igniter may be provided adjacent to the injection line ( 38 ).
- the injection gas is supplied to the injector apparatus ( 36 ), including the injection wellbores ( 40 ), via the injection gas source ( 41 ).
- the injection gas is air or some other suitable oxygen containing gas.
- a combustion zone ( 70 ) forms and expands from the injection line ( 38 ), generally away from the primary production plane ( 30 ) and upward toward the venting positions ( 34 ).
- the vent wells ( 32 ) assist in the progression of the combustion zone ( 70 ) away from the injection line ( 38 ) and in influencing the flow of the injection gas through the reservoir ( 22 ) away from the primary production length ( 28 ).
- a pool ( 72 ) of hydrocarbon liquid may form around the primary production length ( 28 ).
- gases contained in the reservoir ( 22 ) may move toward the venting positions ( 34 ), particularly the venting positions ( 34 ) which are substantially within the primary production plane ( 30 ) or which are laterally offset from the primary production plane ( 30 ) by relatively small distances.
- the likelihood of early breakthrough or fingering of the injection gas or combustion gases is reduced.
- the likelihood of early breakthrough or fingering of gases at the primary production length ( 28 ) may be further reduced by controlling the drawdown pressure along the primary production length ( 28 ).
- the production life of the method and the drainage area of hydrocarbons from the reservoir ( 22 ) is enhanced through the use of the offset liquid production wellbores ( 42 , 50 , 56 , 64 ).
- the hydrocarbon liquid is produced from the primary liquid production wellbore and from the first set of offset liquid production wellbores (consisting of the first offset liquid production wellbore ( 42 ) and the third offset liquid production wellbore ( 56 )).
- the injection gas continues to be injected along the injection line ( 38 ) while the hydrocarbon liquid is produced from the primary liquid production wellbore ( 26 ), the first offset liquid production wellbore ( 42 ) and the third offset liquid production wellbore ( 56 ).
- Gases contained in the reservoir ( 22 ) are vented through the same venting positions ( 34 ) as in the first stage and/or from other venting positions ( 34 ) which are laterally offset from the primary production plane ( 30 ) by a greater distance from those from which venting occurred in the first stage. Gases may also be vented through the offset liquid production wellbores ( 42 , 56 ).
- production of the hydrocarbon liquid from the primary liquid production wellbore ( 26 ) ceases upon detection of a threshold amount of a breakthrough gas at the primary liquid production wellbore ( 26 ).
- the threshold amount of the breakthrough gas may be comprised of any amount of oxygen.
- the formation of the combustion zone ( 70 ) and the pool ( 72 ) of hydrocarbon liquid may tend to accelerate away from the primary production plane ( 30 ), which may result in an increase in the production rate of the hydrocarbon liquid from the first set of offset liquid production wellbores ( 42 , 56 ).
- the method may progress to a fourth stage.
- the hydrocarbon liquid is produced from the first set of offset liquid production wellbores (consisting of the first offset liquid production wellbore ( 42 ) and the third offset liquid production wellbore ( 56 )) and from the second set of offset liquid production wellbores (consisting of the second offset liquid production wellbore ( 50 ) and the fourth offset liquid production wellbore ( 64 )).
- the injection gas continues to be injected along the injection line ( 38 ) while the hydrocarbon liquid is produced from the offset liquid production wellbores ( 42 , 50 , 56 , 64 ).
- Gases contained in the reservoir ( 22 ) are vented through the same venting positions ( 34 ) as in the second stage and/or from other venting positions ( 34 ) which are laterally offset from the primary production plane ( 30 ) by a greater distance from those from which venting occurred in the second stage. Gases may also be vented through the offset liquid production wellbores ( 42 , 50 , 56 , 64 ).
- production of the hydrocarbon liquid from the first set of offset liquid production wellbores ( 42 , 56 ) ceases upon detection of a threshold amount of a breakthrough gas at the first set of offset liquid production wellbores ( 42 , 56 ).
- the threshold amount of the breakthrough gas may be comprised of any amount of oxygen.
- the injection gas may be injected into the reservoir along the offset production lengths ( 44 , 52 ) of the first set of offset liquid production wellbores ( 42 , 56 ), while injection of the injection gas into the reservoir ( 22 ) along the injection line ( 38 ) either ceases or continues.
- some or all of the gases vented from the vent wells ( 32 ) may be injected into the reservoir ( 22 ) along the injection line ( 38 ) and/or along the primary production length ( 28 ) in order to sequester the gases and/or increase or maintain the pressure in the reservoir ( 22 ).
- Test 2 Two separate laboratory tests (Test 1 and Test 2) were conducted for the primary purpose of proving the concept of the invention. Both tests used MacKay River bitumen having a viscosity of 536,000 centipoise at 15° Celsius. In both tests, a sand pack was saturated with dead bitumen. In both tests, a start-up procedure was employed which involved pre-heating of the reservoir ( 22 ) with electrical heaters and injection of nitrogen gas to create a hot depleted zone adjacent to the injection line ( 38 ) and the primary liquid production wellbore ( 26 ).
- Test 1 utilized a model which included a two-dimensional rectangular vessel measuring 60 centimeters wide by 30 centimeters deep by 10 centimeters long, packed with 20/40 silica sand in order to provide a permeability of 110 Darcies.
- the model further included a single horizontal injection wellbore ( 40 ), a primary liquid production wellbore ( 26 ), a first set of offset liquid production wellbores consisting of a first offset liquid production wellbore ( 42 ), a second set of offset liquid production wellbores consisting of a second offset liquid production wellbore ( 50 ), and two vent wells ( 32 ).
- a single separator/back pressure regulator was used to control each of the liquid production wellbores ( 26 , 42 , 50 ) and the vent wells ( 32 ).
- Test 1 combustion was initiated, but was sustained for only about one hour.
- the heat loss from the large surface area of the two-dimensional model was significant, and is believed to have adversely affected the development and propagation of the combustion zone ( 70 ).
- Test 2 utilized a model which included a cylindrical three-dimensional vessel measuring 36 centimeters in diameter and 60 centimeters long, packed with sand in order to provide a permeability of 20 Darcies.
- the model further included a single horizontal injection wellbore ( 40 ), a primary liquid production wellbore ( 26 ), a first set of offset liquid production wellbores consisting of a first offset liquid production wellbore ( 42 ), a second set of offset liquid production wellbores consisting of a second offset liquid production wellbore ( 50 ), and two vent wells ( 32 ).
- the pressures in the liquid production wellbores ( 26 , 42 , 50 ) and in the vent wells ( 32 ) were independently controllable.
- Test 2 a constant air injection rate of 16 liters per minute was used, while the drawdown pressures of the wellbores ( 26 , 32 , 42 , 50 ) were adjusted and controlled in order to direct the development and movement of the combustion zone ( 70 ) and in order to control the production of breakthrough gas at the wellbores ( 26 , 42 , 50 ). In Test 2, combustion was sustained for longer than 1200 minutes.
- Test 1 and Test 2 appeared to demonstrate that low heat loss is very important for a successful test of ISC processes, having regard to the poor results obtained from the model of Test 1, which included a two-dimensional vessel.
- Test 2 appeared to demonstrate that the method of the invention is feasible and may be characterized by relatively high oil recovery, relatively high oxygen utilization, and relatively low cumulative injected oxygen to oil produced ratio (OOR).
- a top-down process ISC process has been disclosed in “Experimental and Numerical Simulations of a Novel Top Down In-Situ Combustion Process”, Coates, R., Lorimer, S., Ivory, J., Society of Petroleum Engineers, SPE 30295, 1995 and elsewhere.
- a simulation study of the present invention was carried out with the STARSTM (Steam, Thermal and Advanced Processes Reservoir Simulator) thermal simulator developed by Computer Modelling Group Ltd. (CMG).
- CMG Computer Modelling Group Ltd.
- the simulation study was aimed at relatively thin Athabasca reservoirs (about 20 meters thick).
- a history match of the results of the top-down ISC experiment was done to validate the model proposed for the simulation study.
- Properties of a virgin Athabasca reservoir were employed, including a published kinetic reaction model (Belgrave, J. D. M., Moore, R. G., Ursenbach, M. G., and Bennion, D.
- Results of a scaled physical laboratory experiment of the top-down ISC process were applied to validate the simulation model.
- the experiment was carried out in a cylindrical sand pack, 29 centimeters in diameter and 40 centimeters in height, for investigating the top-down ISC process where the gravitational force was scaled to be dominant over the capillary force.
- the sand pack consisted of 40-70 mesh sand and had a measured permeability of approximately 60 Darcies and porosity of 0.33.
- the sand pack was saturated with dead Athabasca bitumen to an initial oil saturation of 0.9.
- a grid of thermocouples was installed to track the combustion front and an external guard heater assembly was commissioned to negate heat losses.
- the sand pack was pre-heated for about 9 hours with a central steam heater 24 centimeters long, which provided localized pre-heating near the injection region but limited pre-heating the entire pack to prevent premature drainage of the bitumen.
- enriched air containing 50% oxygen was injected to the top of the vessel, while oil and gas were produced from a 20 cm horizontal well located at the vessel bottom. The test lasted about 22 hours, including the pre-heating time.
- the CMG STARSTM based model consists of seven fluid components: water, maltene, asphaltene, N 2 , CO 2 , O 2 , and coke.
- Athabasca bitumen is characterized by a two pseudo-component mixture: 91.5 mole % maltene and 8.5 mole % asphaltene.
- the model includes the combustion reactions of the pseudo-components proposed by Belgrave and Moore. This reaction model is based upon experimental studies of thermal cracking reactions and low temperature oxidation of Athabasca bitumen, and published data for the high temperature oxidation of coke. The model allows bitumen to undergo density and viscosity increases, as well as reduced reactivity to oxidation, with increased oxidation presence.
- the reaction types utilized by the model were as follows:
- the model also provides for a viscosity-temperature relationship of Athabasca bitumen, in which a linear log equation is assumed for the viscosity mixing rule.
- the relationship indicates very high viscosity of the bitumen at room temperature, about 800,000 centioise, which is nearly seven times higher than that in the Belgrave study.
- a symmetrical half of the sand pack was modeled with a radial coordinate system having 14 by 7 by 20 grid blocks, for a total of 1,960 blocks. Each of the blocks is 1 centimeter in radial direction and 2 centimeters in height.
- the pre-heating step was simulated by supplying heat to the top 12 central blocks (24 centimeters) to maintain the temperature at 225° C. for about nine hours.
- the temperature distribution from the simulation at the end of the pre-heating step compares reasonably well with the measured profile.
- the simulation assumes no heat loss through the side wall of the vessel because the temperature drop across the vessel wall was constantly monitored during the test and reduced by the external guard heater assembly. However, small heat losses could have occurred through the overburden and underburden insulation blocks in the actual experiment and were accounted for in the model.
- the actual injection rates of the enriched air and back-pressure of the horizontal well were prescribed in the model. Quality of the match is primarily judged by comparing the measured and model bitumen production. Several simulation runs were made with different relative permeability curves to obtain the match. It is noted that the injection and production volumes from the simulation were multiplied by two for comparing with the laboratory data since only half of the sand pack was modeled. Because the actual air rates were specified, the injection volume from the simulation falls in line with the laboratory data, but occurs only when sufficient bitumen is produced. If not, the air injectivity would be lower than the actual due to insufficient voidage in the sand pack and the constraint of back-pressure imposed on the system.
- OOR is an indicator for the efficiency of oxygen utilization in the process, very much like injected steam to bitumen produced (SOR) as an indicator for the steam processes.
- the numerical model for studying the method of the invention includes the same kinetic reaction model and fluid properties as that used for the top-down ISC experiments, and the reservoir properties and initial conditions as provided in Table 2.
- the reservoir ( 22 ) element in the model is 100 m wide, 1,000 m long, and 20 m high. For a two-dimensional simulation, the reservoir is divided into 100 ⁇ 1 ⁇ 20 grid blocks. Reservoir conditions were specified the same as the top-down ISC experiments.
- the numerical model is a non-symmetrical model in which offset liquid production wellbores ( 42 , 50 ) are located only on one side of the primary production plane ( 30 ).
- a primary liquid production wellbore ( 26 ) having a primary production length ( 28 ) of one thousand (1000) meters is located at the bottom and left-most block at 7 meters directly below the injection line ( 38 ).
- First and second sets of offset liquid production wellbores ( 42 , 50 ) are laterally offset from the primary production plane ( 30 ) by 50 meters and 100 meters respectively.
- the offset production lengths ( 44 , 52 ) are at the same level in the reservoir ( 22 ) as the primary production length ( 28 ) and are located on one side of the primary production plane ( 30 ).
- the vent wells ( 32 ) were excluded from the model so that the results of the simulation could be compared with an analogous steam process using the same system ( 20 ) configuration.
- the method of the invention was initiated with steam injection into the injection wellbore ( 40 ) for 130 days to establish communication between the injection well ( 40 ) and the primary liquid production wellbore ( 26 ) and to create a small steam chamber. No attempt was made to optimize the start-up procedure, which was followed by injecting 25° C. air containing 21 volume % of oxygen.
- the bottom-hole pressure of the injection well ( 40 ) was maintained constant at 5 MPa, while a drawdown pressure of 200 kPa was maintained at the primary liquid production wellbore ( 26 ). If oxygen was detected at the primary liquid production wellbore ( 26 ), production therefrom was choked back to maintain an oxygen bypass rate at the primary liquid production wellbore ( 26 ) of less than 3 ⁇ 10 4 standard m 3 /day.
- SAGD steam assisted gravity drainage
- Instantaneous oil production rates and calendar day oil production rates of the two processes are shown in FIG. 8 and FIG. 9 respectively.
- the production rates from the multi-stage SAGD process are shown to be higher than that of the method of the invention during the first 41 ⁇ 2 years of operation.
- the combustion zone ( 70 ) approaches the first set of offset liquid production wellbores ( 42 )
- the production rates of the method of the invention pick up significantly, with the calendar day oil production rate of the method of the invention subsequently exceeding that of the multi-stage SAGD process.
- the calendar day oil production rate of the method of the invention is 122.1 m 3 /d as compared to 95.4 m 3 /d for the multi-stage SAGD process.
- the corresponding calendar day oil production rates per well pair for the method of the invention and the multi-stage SAGD process are 81.4 m 3 /d and 63.6 m 3 /d respectively.
- the calendar day oil production rate for the multi-stage SAGD process appears reasonable when compared with the production from a conventional SAGD process for a 20 m thick Athabasca reservoir with a 6.7 hectare well pair spacing.
- the reservoir ( 22 ) in the simulation model contained 5.61 ⁇ 10 5 m 3 of original oil in place (OOIP).
- OOIP original oil in place
- FIG. 11 depicts the cumulative oxygen to produced oil ratio (OOR) for the method of the invention and the cumulative steam to produced oil ratio (SOR) for the multi-stage SAGD process.
- the cumulative OOR for the method of the invention begins at a very low value but increases steadily with time, similar to the upward trending behavior seen in the laboratory test.
- the ratio reached 706 at the end of the simulation run, which was about three times the maximum ratio which was observed in the laboratory test.
- the cumulative SOR of the multi-stage SAGD process was high during the start-up period, and dropped to 3.2 as the steam interface moved past the first set of offset liquid production wellbores ( 42 ). Thereafter, the cumulative SOR climbed gradually to 3.7 on day 3,563 of the simulation.
- the progression of the combustion zone ( 70 ) during the performance of the method of the invention is shown from the temperature distributions over the reservoir ( 22 ) cross section in FIG. 12 on day 3,519 of the simulation.
- the band of the combustion zone ( 70 ) becomes increasingly broader and hotter as it moves away from the injection line ( 38 ).
- the temperature reaches as high as 1,000° C., and the combustion zone ( 70 ) extends nearly 50 meters across certain layers as the combustion zone ( 70 ) approaches the first set of offset liquid production wellbores ( 42 ) on day 2,137 of the simulation.
- Oxygen consumption increases dramatically at these times as seen in the cumulative OOR curve in FIG. 11 .
- the increase in the oxygen uptake is due to the occurrence of a high temperature oxidation reaction over a large spreading hot zone.
- Water may be co-injected or the air injection pressure and/or rate may be lowered in order to inhibit the expanding of the combustion zone ( 70 ).
- the air injection pressure was kept constant at 5 MPa throughout the simulation, and no attempt was made to optimize the process.
- the calendar day oil production rate of the method of the invention over 10 years of operations is 81.4 m 3 /day per equivalent SAGD well pair, which is 28% higher than that obtained with the multi-stage SAGD process.
- the energy requirement for the method of the invention is 6.5 GJ/m 3 of oil produced, which is 71% less than the energy requirement for the multi-stage SAGD process.
Abstract
Description
-
- (a) a primary liquid production wellbore having a substantially horizontal primary production length which extends through the reservoir, wherein the primary production length is positioned substantially within a vertical primary production plane;
- (b) at least one vent well in fluid communication with the reservoir at a venting position in the reservoir which is relatively higher in the reservoir than the primary production length;
- (c) an injector apparatus in fluid communication with the reservoir along an injection line in the reservoir which is substantially parallel with the primary production plane, wherein the injection line extends along at least a portion of the primary production length, wherein the injection line is relatively higher in the reservoir than the primary production length, and wherein the injection line is relatively lower in the reservoir than the venting position; and
- (d) an injection gas source connected with the injector apparatus, for supplying an injection gas containing oxygen to the injector apparatus for injecting along the injection line in order to cause combustion of the hydrocarbons contained in the reservoir.
-
- (a) providing a primary liquid production wellbore having a substantially horizontal primary production length which extends through the reservoir, wherein the primary production length is positioned substantially within a vertical primary production plane;
- (b) providing at least one vent well in fluid communication with the reservoir at a venting position in the reservoir which is relatively higher in the reservoir than the primary production length;
- (c) providing an injector apparatus in fluid communication with the reservoir along an injection line in the reservoir which is substantially parallel with the primary production plane, wherein the injection line extends along at least a portion of the primary production length, wherein the injection line is relatively higher in the reservoir than the primary production length, and wherein the injection line is relatively lower in the reservoir than the venting position;
- (d) injecting an injection gas containing oxygen into the reservoir along the injection line in order to cause combustion of the hydrocarbons contained in the reservoir, thereby heating the reservoir so that the hydrocarbon liquid drains toward the primary liquid production wellbore;
- (e) producing the hydrocarbon liquid from the primary liquid production wellbore; and
- (f) venting, from the vent well, gases contained in the reservoir.
-
- 1. opening the vent wells (32) appeared to direct the development of the combustion zone (70) upward toward the vent wells (32);
- 2. opening the vent wells (32) resulted in no breakthrough gas being produced at the liquid production wellbores (26,42,50);
- 3. opening the second offset liquid production wellbore (50) caused a drop in the amount of breakthrough gas which was produced at the primary liquid production wellbore (26) and the first offset liquid production wellbore (42);
- 4. the oxygen concentration in the gases vented from the vent wells (32) dropped to zero or near zero initially upon opening of the vent wells (32), but increased gradually over time;
- 5. oxygen utilization reached 78% by the end of
Test 2; - 6. the final recovery of oil from the model in
Test 2 was estimated to be approximately 90%, including oil recovered during the pre-heating; - 7. the production of hydrocarbon liquid from the liquid production wellbores (26,42,50) was unsteady and fluctuating while the vent wells (32) were open;
- 8. the oil production rate was lower when the vent wells (32) were open, suggesting that gas drive toward the liquid production wellbores (26,42,50) may contribute to oil production rates;
- 9. the cumulative injected air to oil produced ratio (OOR) in
Test 2 exhibited a decreasing trend, suggesting that combustion became more efficient over the course ofTest 2, with the final OOR being about 1,100; - 10. the compression energy to oil produced ratio in
Test 2 was about 2.1 GJ/m3, which is approximately equivalent to the energy required for a steam assisted gravity drainage (SAGD) process involving a cumulative steam to oil produced ratio (SOR) of about 0.9.
dC r /dt=A rexp(Er/RT) C 1 n C 2 m
TABLE 1 | |||||
Reaction | Activation | Heat Of | |||
Frequency | Energy (Er), | Reaction, | |||
Reaction | Factor (Ar) | J/gmole | J/gmole | ||
1 | 7.86E+17 | 2.35E+05 | 0 | ||
2 | 3.51E+14 | 1.77E+05 | 0 | ||
3 | 1.18E+14 | 1.76E+05 | 0 | ||
4 | 1.11E+10 | 8.67E+04 | 1.30E+06 | ||
5 | 3.58E+09 | 1.86E+05 | 2.86E+06 | ||
6 | 1.59E+02 | 3.48E+04 | 3.50E+05 | ||
TABLE 2 | |||
Reservoir Thickness, m | 20 | ||
Reservoir Initial Pressure, |
2 | ||
Reservoir Initial Temperature, ° C. | 13 | ||
Porosity | 0.33 | ||
Absolute Horizontal Permeability, | 4 | ||
Darcy | |||
Absolute Vertical Permeability, Darcy | 0.4 | ||
Water Saturation | 0.15 | ||
Oil Saturation | 0.85 | ||
|
0 | ||
Asphaltene Content in Bitumen, mole % | 8.5 | ||
Bitumen Viscosity @ 13° C., mPa s | 2.9 × 106 | ||
Maltene Viscosity @ 13° C., mPa s | 1.2 × 106 | ||
Asphaltene Viscosity @ 13° C., mPa s | 5.5 × 1010 | ||
-
- 1. air injection was replaced by steam injection,
- 2. the injection pressure was reduced to 2.5 MPa from 5.0 MPa, and
- 3. a 15° C. steam trap constraint was imposed on each of the primary liquid production wellbore (26), the first set of offset liquid production wellbores (42) and the second set of offset liquid production wellbores (50).
(e) Simulation Results
TABLE 3 | |||
Air Ambient Pressure, |
100 | ||
Air Injection Pressure @ 15° C. | 5000 | ||
|
50 | ||
Oxygen/Oil Ratio | 706 | ||
Air/Oil Volume Ratio, m3/m3 | 3362 | ||
k = Cp/Cv @ 20° C. | 1.20 | ||
Compressor Efficiency, % | 80 | ||
Power Generator Efficiency, % | 30 | ||
Adiabatic Compression, hp/(m3/d oil) | 118.3 | ||
Isothermal Compression, hp/(m3/d oil) | 83.9 | ||
Conversion Factor, GJ/hp-d | 0.0644 | ||
Average Compression Energy, GJ/m3 oil | 6.5 | ||
TABLE 4 | |||
Steam Vapour Energy @ 10 MPa, GJ/L m3 | 2.725 | ||
Steam Condensate Energy @ 10 MPa, GJ/L m3 | 1.408 | ||
Steam Quality at Boiler, % | 75.0 | ||
Boiler Efficiency, % | 85 | ||
Heat Recovery From Hot Condensate, % | 75 | ||
Preheated BFW Temperature, ° C. | 120 | ||
Energy In Preheated BFW, GJ/m3 | 0.44 | ||
Energy to Generate 100% Steam at Plant, GJ/L m3 | 2.83 | ||
Steam Quality Drop by Heat Loss, % | 1.0 | ||
Steam Quality Drop by Pressure Letdown, % | 5.0 | ||
Energy to Generate 100% Steam at WH, GJ/Liq. m3 | 3.01 | ||
SOR | 3.7 | ||
Energy Consumption, GJ/m3 oil | 11.1 | ||
Claims (47)
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/022,310 US7740062B2 (en) | 2008-01-30 | 2008-01-30 | System and method for the recovery of hydrocarbons by in-situ combustion |
CA2650130A CA2650130C (en) | 2008-01-30 | 2009-01-16 | System and method for the recovery of hydrocarbons by in-situ combustion |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/022,310 US7740062B2 (en) | 2008-01-30 | 2008-01-30 | System and method for the recovery of hydrocarbons by in-situ combustion |
Publications (2)
Publication Number | Publication Date |
---|---|
US20090188667A1 US20090188667A1 (en) | 2009-07-30 |
US7740062B2 true US7740062B2 (en) | 2010-06-22 |
Family
ID=40898046
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/022,310 Active 2028-09-07 US7740062B2 (en) | 2008-01-30 | 2008-01-30 | System and method for the recovery of hydrocarbons by in-situ combustion |
Country Status (2)
Country | Link |
---|---|
US (1) | US7740062B2 (en) |
CA (1) | CA2650130C (en) |
Cited By (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20090044940A1 (en) * | 2006-02-15 | 2009-02-19 | Pfefferle William C | Method for CAGD recovery of heavy oil |
US9163491B2 (en) | 2011-10-21 | 2015-10-20 | Nexen Energy Ulc | Steam assisted gravity drainage processes with the addition of oxygen |
US9328592B2 (en) | 2011-07-13 | 2016-05-03 | Nexen Energy Ulc | Steam anti-coning/cresting technology ( SACT) remediation process |
CN105545274A (en) * | 2015-12-09 | 2016-05-04 | 中国石油天然气股份有限公司 | Well pattern and method for improving fire flooding effect of thick-layer heavy oil reservoir |
US20170002638A1 (en) * | 2011-07-13 | 2017-01-05 | Nexen Energy Ulc | Use of steam assisted gravity drainage with oxygen ("sagdox") in the recovery of bitumen in thin pay zones |
US9562424B2 (en) | 2013-11-22 | 2017-02-07 | Cenovus Energy Inc. | Waste heat recovery from depleted reservoir |
US9803456B2 (en) | 2011-07-13 | 2017-10-31 | Nexen Energy Ulc | SAGDOX geometry for impaired bitumen reservoirs |
US9828841B2 (en) | 2011-07-13 | 2017-11-28 | Nexen Energy Ulc | Sagdox geometry |
US20180216450A1 (en) * | 2016-08-25 | 2018-08-02 | Conocophillips Company | Well configuration for coinjection |
Families Citing this family (21)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CA2549614C (en) * | 2006-06-07 | 2014-11-25 | N-Solv Corporation | Methods and apparatuses for sagd hydrocarbon production |
US8132620B2 (en) * | 2008-12-19 | 2012-03-13 | Schlumberger Technology Corporation | Triangle air injection and ignition extraction method and system |
CA2678347C (en) * | 2009-09-11 | 2010-09-21 | Excelsior Energy Limited | System and method for enhanced oil recovery from combustion overhead gravity drainage processes |
CA2698454C (en) * | 2010-03-30 | 2011-11-29 | Archon Technologies Ltd. | Improved in-situ combustion recovery process using single horizontal well to produce oil and combustion gases to surface |
RU2471974C2 (en) * | 2011-03-29 | 2013-01-10 | Пелых Николай Михайлович | Treatment method of bottom-hole formation zone, and device for its implementation |
CA2791323A1 (en) * | 2011-10-21 | 2013-04-21 | Nexen Inc. | Steam assisted gravity drainage processes with the addition of oxygen addition |
CA2791318A1 (en) * | 2011-10-24 | 2013-04-24 | Nexen Inc. | Steam flooding with oxygen injection, and cyclic steam stimulation with oxygen injection |
US8960317B2 (en) | 2011-11-25 | 2015-02-24 | Capri Petroleum Technologies Ltd. | Horizontal well line-drive oil recovery process |
WO2013075206A1 (en) * | 2011-11-25 | 2013-05-30 | Archon Technologies Ltd. | Horizontal well line-drive oil recovery process |
US20130146284A1 (en) * | 2011-12-07 | 2013-06-13 | Archon Technologies Ltd. | Staggered horizontal well oil recovery process |
CA2771703A1 (en) * | 2012-03-16 | 2013-09-16 | Sunshine Oilsands Ltd. | Fully controlled combustion assisted gravity drainage process |
WO2013166586A1 (en) * | 2012-05-07 | 2013-11-14 | Nexen Energy Ulc | Satellite steam-assisted gravity drainage with oxygen (sagdox) system for remote recovery of hydrocarbons |
WO2014000096A1 (en) * | 2012-06-29 | 2014-01-03 | Nexen Energy Ulc | Sagd control in leaky reservoirs |
WO2014000095A1 (en) * | 2012-06-29 | 2014-01-03 | Nexen Energy Ulc | Sagdox operation in leaky bitumen reservoirs |
CA2886977C (en) * | 2012-10-02 | 2019-04-30 | Conocophillips Company | Em and combustion stimulation of heavy oil |
US10718186B2 (en) * | 2014-08-22 | 2020-07-21 | Chevron U.S.A. Inc. | Flooding analysis tool and method thereof |
WO2016037291A1 (en) * | 2014-09-11 | 2016-03-17 | Resource Innovations Inc. | Method of capturing and venting non-condensable reservoir gases in enhanced oil recovery applications |
CN109723417A (en) * | 2019-01-07 | 2019-05-07 | 中国海洋石油集团有限公司 | A kind of recovery method turning fireflood suitable for oil-sand SAGD development late stage |
CN110344798B (en) * | 2019-06-20 | 2021-08-03 | 中国石油天然气股份有限公司 | Gravity fireflood method for improving gravity fireflood regulation and control by utilizing horizontal exhaust well |
CN112459756B (en) * | 2020-11-24 | 2021-09-03 | 北京科技大学 | Visualization model, visualization device and visualization method for gas overlap phenomenon |
CN114961669A (en) * | 2022-06-15 | 2022-08-30 | 扬州华宝石油仪器有限公司 | Ignition experiment device for simulating underground and method for simulating and collecting ignition data |
Citations (62)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2365591A (en) | 1942-08-15 | 1944-12-19 | Ranney Leo | Method for producing oil from viscous deposits |
US2901043A (en) | 1955-07-29 | 1959-08-25 | Pan American Petroleum Corp | Heavy oil recovery |
US2958519A (en) | 1958-06-23 | 1960-11-01 | Phillips Petroleum Co | In situ combustion process |
US2969226A (en) * | 1959-01-19 | 1961-01-24 | Pyrochem Corp | Pendant parting petro pyrolysis process |
US3017168A (en) * | 1959-01-26 | 1962-01-16 | Phillips Petroleum Co | In situ retorting of oil shale |
US3044545A (en) | 1958-10-02 | 1962-07-17 | Phillips Petroleum Co | In situ combustion process |
US3132692A (en) * | 1959-07-27 | 1964-05-12 | Phillips Petroleum Co | Use of formation heat from in situ combustion |
US3441083A (en) | 1967-11-09 | 1969-04-29 | Tenneco Oil Co | Method of recovering hydrocarbon fluids from a subterranean formation |
US3727686A (en) | 1971-03-15 | 1973-04-17 | Shell Oil Co | Oil recovery by overlying combustion and hot water drives |
US3794113A (en) | 1972-11-13 | 1974-02-26 | Mobil Oil Corp | Combination in situ combustion displacement and steam stimulation of producing wells |
US4356866A (en) | 1980-12-31 | 1982-11-02 | Mobil Oil Corporation | Process of underground coal gasification |
US4384613A (en) | 1980-10-24 | 1983-05-24 | Terra Tek, Inc. | Method of in-situ retorting of carbonaceous material for recovery of organic liquids and gases |
US4390067A (en) | 1981-04-06 | 1983-06-28 | Exxon Production Research Co. | Method of treating reservoirs containing very viscous crude oil or bitumen |
US4397356A (en) | 1981-03-26 | 1983-08-09 | Retallick William B | High pressure combustor for generating steam downhole |
US4422505A (en) | 1982-01-07 | 1983-12-27 | Atlantic Richfield Company | Method for gasifying subterranean coal deposits |
US4454916A (en) | 1982-11-29 | 1984-06-19 | Mobil Oil Corporation | In-situ combustion method for recovery of oil and combustible gas |
US4474237A (en) | 1983-12-07 | 1984-10-02 | Mobil Oil Corporation | Method for initiating an oxygen driven in-situ combustion process |
US4535845A (en) | 1983-09-01 | 1985-08-20 | Texaco Inc. | Method for producing viscous hydrocarbons from discrete segments of a subterranean layer |
US4545430A (en) | 1982-08-27 | 1985-10-08 | Retallick William B | Catalytic combustor having spiral shape |
US4566536A (en) | 1983-11-21 | 1986-01-28 | Mobil Oil Corporation | Method for operating an injection well in an in-situ combustion oil recovery using oxygen |
US4566537A (en) | 1984-09-20 | 1986-01-28 | Atlantic Richfield Co. | Heavy oil recovery |
US4573531A (en) | 1980-02-21 | 1986-03-04 | Vsesojuznoe Nauchno-Proizvod-Stvennoe Obiedinenie "Sojuzpromgaz" | Method of underground gasification of coal seam |
US4574884A (en) * | 1984-09-20 | 1986-03-11 | Atlantic Richfield Company | Drainhole and downhole hot fluid generation oil recovery method |
US4625800A (en) | 1984-11-21 | 1986-12-02 | Mobil Oil Corporation | Method of recovering medium or high gravity crude oil |
US4653583A (en) | 1985-11-01 | 1987-03-31 | Texaco Inc. | Optimum production rate for horizontal wells |
US4662441A (en) | 1985-12-23 | 1987-05-05 | Texaco Inc. | Horizontal wells at corners of vertical well patterns for improving oil recovery efficiency |
US4682652A (en) | 1986-06-30 | 1987-07-28 | Texaco Inc. | Producing hydrocarbons through successively perforated intervals of a horizontal well between two vertical wells |
US4696345A (en) | 1986-08-21 | 1987-09-29 | Chevron Research Company | Hasdrive with multiple offset producers |
US4700779A (en) | 1985-11-04 | 1987-10-20 | Texaco Inc. | Parallel horizontal wells |
US4702314A (en) | 1986-03-03 | 1987-10-27 | Texaco Inc. | Patterns of horizontal and vertical wells for improving oil recovery efficiency |
US4718489A (en) | 1986-09-17 | 1988-01-12 | Alberta Oil Sands Technology And Research Authority | Pressure-up/blowdown combustion - a channelled reservoir recovery process |
US4718485A (en) | 1986-10-02 | 1988-01-12 | Texaco Inc. | Patterns having horizontal and vertical wells |
US4794987A (en) | 1988-01-04 | 1989-01-03 | Texaco Inc. | Solvent flooding with a horizontal injection well and drive fluid in gas flooded reservoirs |
US4834179A (en) | 1988-01-04 | 1989-05-30 | Texaco Inc. | Solvent flooding with a horizontal injection well in gas flooded reservoirs |
US4850429A (en) | 1987-12-21 | 1989-07-25 | Texaco Inc. | Recovering hydrocarbons with a triangular horizontal well pattern |
US5016709A (en) * | 1988-06-03 | 1991-05-21 | Institut Francais Du Petrole | Process for assisted recovery of heavy hydrocarbons from an underground formation using drilled wells having an essentially horizontal section |
US5033546A (en) | 1988-12-30 | 1991-07-23 | Institut Francais Du Petrole | Production simulation process by pilot test in a hydrocarbon deposit |
US5046559A (en) | 1990-08-23 | 1991-09-10 | Shell Oil Company | Method and apparatus for producing hydrocarbon bearing deposits in formations having shale layers |
US5211230A (en) | 1992-02-21 | 1993-05-18 | Mobil Oil Corporation | Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion |
US5217076A (en) * | 1990-12-04 | 1993-06-08 | Masek John A | Method and apparatus for improved recovery of oil from porous, subsurface deposits (targevcir oricess) |
US5273111A (en) | 1991-07-03 | 1993-12-28 | Amoco Corporation | Laterally and vertically staggered horizontal well hydrocarbon recovery method |
US5339897A (en) | 1991-12-20 | 1994-08-23 | Exxon Producton Research Company | Recovery and upgrading of hydrocarbon utilizing in situ combustion and horizontal wells |
CA2096034A1 (en) | 1993-05-07 | 1994-11-08 | Kenneth Edwin Kisman | Horizontal Well Gravity Drainage Combustion Process for Oil Recovery |
CA2176639A1 (en) | 1995-06-23 | 1996-12-24 | Malcolm Greaves | Oilfield In-Situ Combustion Process |
CA2255071A1 (en) | 1997-12-11 | 1999-06-11 | Conrad Ayasse | Oilfield in-situ upgrading process |
US5935419A (en) | 1996-09-16 | 1999-08-10 | Texaco Inc. | Methods for adding value to heavy oil utilizing a soluble metal catalyst |
US6016867A (en) | 1998-06-24 | 2000-01-25 | World Energy Systems, Incorporated | Upgrading and recovery of heavy crude oils and natural bitumens by in situ hydrovisbreaking |
US6016868A (en) | 1998-06-24 | 2000-01-25 | World Energy Systems, Incorporated | Production of synthetic crude oil from heavy hydrocarbons recovered by in situ hydrovisbreaking |
CA2246461A1 (en) | 1998-09-02 | 2000-03-02 | Conrad Ayasse | Toe-to-heel oil recovery process |
US6167966B1 (en) | 1998-09-04 | 2001-01-02 | Alberta Research Council, Inc. | Toe-to-heel oil recovery process |
US6530965B2 (en) | 2001-04-27 | 2003-03-11 | Colt Engineering Corporation | Method of converting heavy oil residuum to a useful fuel |
US6533038B2 (en) | 1999-12-10 | 2003-03-18 | Laurie Venning | Method of achieving a preferential flow distribution in a horizontal well bore |
US20040050547A1 (en) | 2002-09-16 | 2004-03-18 | Limbach Kirk Walton | Downhole upgrading of oils |
US20050082057A1 (en) | 2003-10-17 | 2005-04-21 | Newton Donald E. | Recovery of heavy oils through in-situ combustion process |
WO2005121504A1 (en) | 2004-06-07 | 2005-12-22 | Archon Technologies Ltd. | Oilfield enhanced in situ combustion process |
WO2006074554A1 (en) | 2005-01-13 | 2006-07-20 | Encana Corporation | In situ combustion in gas over bitumen formations |
US20060162923A1 (en) | 2005-01-25 | 2006-07-27 | World Energy Systems, Inc. | Method for producing viscous hydrocarbon using incremental fracturing |
US20060207762A1 (en) | 2004-06-07 | 2006-09-21 | Conrad Ayasse | Oilfield enhanced in situ combustion process |
WO2007033462A1 (en) | 2005-09-23 | 2007-03-29 | Alberta Research Council, Inc. | Toe-to-heel waterflooding with progressive blockage of the toe region |
WO2007095764A1 (en) | 2006-02-27 | 2007-08-30 | Archon Technologies Ltd. | Diluent-enhanced in-situ combustion hydrocarbon recovery process |
US20070284108A1 (en) * | 2006-04-21 | 2007-12-13 | Roes Augustinus W M | Compositions produced using an in situ heat treatment process |
US7516789B2 (en) * | 2005-01-13 | 2009-04-14 | Encana Corporation | Hydrocarbon recovery facilitated by in situ combustion utilizing horizontal well pairs |
-
2008
- 2008-01-30 US US12/022,310 patent/US7740062B2/en active Active
-
2009
- 2009-01-16 CA CA2650130A patent/CA2650130C/en active Active
Patent Citations (72)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2365591A (en) | 1942-08-15 | 1944-12-19 | Ranney Leo | Method for producing oil from viscous deposits |
US2901043A (en) | 1955-07-29 | 1959-08-25 | Pan American Petroleum Corp | Heavy oil recovery |
US2958519A (en) | 1958-06-23 | 1960-11-01 | Phillips Petroleum Co | In situ combustion process |
US3044545A (en) | 1958-10-02 | 1962-07-17 | Phillips Petroleum Co | In situ combustion process |
US2969226A (en) * | 1959-01-19 | 1961-01-24 | Pyrochem Corp | Pendant parting petro pyrolysis process |
US3017168A (en) * | 1959-01-26 | 1962-01-16 | Phillips Petroleum Co | In situ retorting of oil shale |
US3132692A (en) * | 1959-07-27 | 1964-05-12 | Phillips Petroleum Co | Use of formation heat from in situ combustion |
US3441083A (en) | 1967-11-09 | 1969-04-29 | Tenneco Oil Co | Method of recovering hydrocarbon fluids from a subterranean formation |
US3727686A (en) | 1971-03-15 | 1973-04-17 | Shell Oil Co | Oil recovery by overlying combustion and hot water drives |
US3794113A (en) | 1972-11-13 | 1974-02-26 | Mobil Oil Corp | Combination in situ combustion displacement and steam stimulation of producing wells |
US4573531A (en) | 1980-02-21 | 1986-03-04 | Vsesojuznoe Nauchno-Proizvod-Stvennoe Obiedinenie "Sojuzpromgaz" | Method of underground gasification of coal seam |
US4384613A (en) | 1980-10-24 | 1983-05-24 | Terra Tek, Inc. | Method of in-situ retorting of carbonaceous material for recovery of organic liquids and gases |
US4356866A (en) | 1980-12-31 | 1982-11-02 | Mobil Oil Corporation | Process of underground coal gasification |
US4397356A (en) | 1981-03-26 | 1983-08-09 | Retallick William B | High pressure combustor for generating steam downhole |
US4390067A (en) | 1981-04-06 | 1983-06-28 | Exxon Production Research Co. | Method of treating reservoirs containing very viscous crude oil or bitumen |
US4422505A (en) | 1982-01-07 | 1983-12-27 | Atlantic Richfield Company | Method for gasifying subterranean coal deposits |
US4545430A (en) | 1982-08-27 | 1985-10-08 | Retallick William B | Catalytic combustor having spiral shape |
US4454916A (en) | 1982-11-29 | 1984-06-19 | Mobil Oil Corporation | In-situ combustion method for recovery of oil and combustible gas |
US4535845A (en) | 1983-09-01 | 1985-08-20 | Texaco Inc. | Method for producing viscous hydrocarbons from discrete segments of a subterranean layer |
US4566536A (en) | 1983-11-21 | 1986-01-28 | Mobil Oil Corporation | Method for operating an injection well in an in-situ combustion oil recovery using oxygen |
US4474237A (en) | 1983-12-07 | 1984-10-02 | Mobil Oil Corporation | Method for initiating an oxygen driven in-situ combustion process |
US4566537A (en) | 1984-09-20 | 1986-01-28 | Atlantic Richfield Co. | Heavy oil recovery |
US4574884A (en) * | 1984-09-20 | 1986-03-11 | Atlantic Richfield Company | Drainhole and downhole hot fluid generation oil recovery method |
US4625800A (en) | 1984-11-21 | 1986-12-02 | Mobil Oil Corporation | Method of recovering medium or high gravity crude oil |
US4653583A (en) | 1985-11-01 | 1987-03-31 | Texaco Inc. | Optimum production rate for horizontal wells |
US4700779A (en) | 1985-11-04 | 1987-10-20 | Texaco Inc. | Parallel horizontal wells |
US4662441A (en) | 1985-12-23 | 1987-05-05 | Texaco Inc. | Horizontal wells at corners of vertical well patterns for improving oil recovery efficiency |
US4702314A (en) | 1986-03-03 | 1987-10-27 | Texaco Inc. | Patterns of horizontal and vertical wells for improving oil recovery efficiency |
US4682652A (en) | 1986-06-30 | 1987-07-28 | Texaco Inc. | Producing hydrocarbons through successively perforated intervals of a horizontal well between two vertical wells |
US4696345A (en) | 1986-08-21 | 1987-09-29 | Chevron Research Company | Hasdrive with multiple offset producers |
US4718489A (en) | 1986-09-17 | 1988-01-12 | Alberta Oil Sands Technology And Research Authority | Pressure-up/blowdown combustion - a channelled reservoir recovery process |
US4718485A (en) | 1986-10-02 | 1988-01-12 | Texaco Inc. | Patterns having horizontal and vertical wells |
US4850429A (en) | 1987-12-21 | 1989-07-25 | Texaco Inc. | Recovering hydrocarbons with a triangular horizontal well pattern |
US4794987A (en) | 1988-01-04 | 1989-01-03 | Texaco Inc. | Solvent flooding with a horizontal injection well and drive fluid in gas flooded reservoirs |
US4834179A (en) | 1988-01-04 | 1989-05-30 | Texaco Inc. | Solvent flooding with a horizontal injection well in gas flooded reservoirs |
US5016709A (en) * | 1988-06-03 | 1991-05-21 | Institut Francais Du Petrole | Process for assisted recovery of heavy hydrocarbons from an underground formation using drilled wells having an essentially horizontal section |
US5033546A (en) | 1988-12-30 | 1991-07-23 | Institut Francais Du Petrole | Production simulation process by pilot test in a hydrocarbon deposit |
US5046559A (en) | 1990-08-23 | 1991-09-10 | Shell Oil Company | Method and apparatus for producing hydrocarbon bearing deposits in formations having shale layers |
US5217076A (en) * | 1990-12-04 | 1993-06-08 | Masek John A | Method and apparatus for improved recovery of oil from porous, subsurface deposits (targevcir oricess) |
CA2046107C (en) | 1991-07-03 | 1994-12-06 | Geryl Owen Brannan | Laterally and vertically staggered horizontal well hydrocarbon recovery method |
US5273111A (en) | 1991-07-03 | 1993-12-28 | Amoco Corporation | Laterally and vertically staggered horizontal well hydrocarbon recovery method |
US5339897A (en) | 1991-12-20 | 1994-08-23 | Exxon Producton Research Company | Recovery and upgrading of hydrocarbon utilizing in situ combustion and horizontal wells |
US5211230A (en) | 1992-02-21 | 1993-05-18 | Mobil Oil Corporation | Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion |
CA2088179A1 (en) | 1992-02-21 | 1993-08-22 | Eugene Ostapovich | Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion |
US5456315A (en) | 1993-05-07 | 1995-10-10 | Alberta Oil Sands Technology And Research | Horizontal well gravity drainage combustion process for oil recovery |
CA2096034A1 (en) | 1993-05-07 | 1994-11-08 | Kenneth Edwin Kisman | Horizontal Well Gravity Drainage Combustion Process for Oil Recovery |
CA2176639A1 (en) | 1995-06-23 | 1996-12-24 | Malcolm Greaves | Oilfield In-Situ Combustion Process |
US5626191A (en) | 1995-06-23 | 1997-05-06 | Petroleum Recovery Institute | Oilfield in-situ combustion process |
US5935419A (en) | 1996-09-16 | 1999-08-10 | Texaco Inc. | Methods for adding value to heavy oil utilizing a soluble metal catalyst |
US6412557B1 (en) | 1997-12-11 | 2002-07-02 | Alberta Research Council Inc. | Oilfield in situ hydrocarbon upgrading process |
CA2255071A1 (en) | 1997-12-11 | 1999-06-11 | Conrad Ayasse | Oilfield in-situ upgrading process |
US6016867A (en) | 1998-06-24 | 2000-01-25 | World Energy Systems, Incorporated | Upgrading and recovery of heavy crude oils and natural bitumens by in situ hydrovisbreaking |
US6016868A (en) | 1998-06-24 | 2000-01-25 | World Energy Systems, Incorporated | Production of synthetic crude oil from heavy hydrocarbons recovered by in situ hydrovisbreaking |
US6328104B1 (en) | 1998-06-24 | 2001-12-11 | World Energy Systems Incorporated | Upgrading and recovery of heavy crude oils and natural bitumens by in situ hydrovisbreaking |
CA2246461A1 (en) | 1998-09-02 | 2000-03-02 | Conrad Ayasse | Toe-to-heel oil recovery process |
US6167966B1 (en) | 1998-09-04 | 2001-01-02 | Alberta Research Council, Inc. | Toe-to-heel oil recovery process |
US6533038B2 (en) | 1999-12-10 | 2003-03-18 | Laurie Venning | Method of achieving a preferential flow distribution in a horizontal well bore |
US6530965B2 (en) | 2001-04-27 | 2003-03-11 | Colt Engineering Corporation | Method of converting heavy oil residuum to a useful fuel |
US20040050547A1 (en) | 2002-09-16 | 2004-03-18 | Limbach Kirk Walton | Downhole upgrading of oils |
US20050082057A1 (en) | 2003-10-17 | 2005-04-21 | Newton Donald E. | Recovery of heavy oils through in-situ combustion process |
US20060207762A1 (en) | 2004-06-07 | 2006-09-21 | Conrad Ayasse | Oilfield enhanced in situ combustion process |
CA2569676A1 (en) | 2004-06-07 | 2005-12-22 | Archon Technologies Ltd. | Oilfield enhanced in situ combustion process |
WO2005121504A1 (en) | 2004-06-07 | 2005-12-22 | Archon Technologies Ltd. | Oilfield enhanced in situ combustion process |
WO2006074554A1 (en) | 2005-01-13 | 2006-07-20 | Encana Corporation | In situ combustion in gas over bitumen formations |
US7516789B2 (en) * | 2005-01-13 | 2009-04-14 | Encana Corporation | Hydrocarbon recovery facilitated by in situ combustion utilizing horizontal well pairs |
US20060162923A1 (en) | 2005-01-25 | 2006-07-27 | World Energy Systems, Inc. | Method for producing viscous hydrocarbon using incremental fracturing |
WO2007033462A1 (en) | 2005-09-23 | 2007-03-29 | Alberta Research Council, Inc. | Toe-to-heel waterflooding with progressive blockage of the toe region |
US20070068674A1 (en) | 2005-09-23 | 2007-03-29 | Alberta Research Council, Inc. | Toe-To-Heel Waterflooding With Progressive Blockage Of The Toe Region |
CA2579854A1 (en) | 2006-02-27 | 2007-08-27 | Archon Technologies Ltd. | Oilfield enhanced in situ combustion process |
WO2007095763A1 (en) | 2006-02-27 | 2007-08-30 | Archon Technologies Ltd. | Oilfield enhanced in situ combustion process |
WO2007095764A1 (en) | 2006-02-27 | 2007-08-30 | Archon Technologies Ltd. | Diluent-enhanced in-situ combustion hydrocarbon recovery process |
US20070284108A1 (en) * | 2006-04-21 | 2007-12-13 | Roes Augustinus W M | Compositions produced using an in situ heat treatment process |
Non-Patent Citations (40)
Title |
---|
Al-Honi, M., Greaves, M. and Zekri, A.Y. (2002) Enhanced Recovery of Medium Crude Oil in Heterogeneous Reservoirs using Air Injection/In-Situ Combustion-Horizontal Well Technology, Petroleum Science and Air Technology, 20(5&6), 655-669. |
Ayasse, C., Bloomer, C., Lynberg E., Boddy, W., Donnelly, J., Greaves, M. (2005) First Field Polot of the THAI process. CIPC, Calgary, AB., Jun. 7-9. |
Belgrave, J.D.M., et al., "A Comprehensive Approach to In Situ Combustion Modeling", paper presented to the SPE/DOE Seventh Symposium on EOR held in Tulsa, OK on Apr. 22-25, 1990. |
Belgrave, J.D.M., Nzekwu, B., and Chhina, H.S. (2007) SADG Optimization with Air Injection. SPE Latin America and Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, Apr. 15-18. |
Coates, R. Lorimer, S. and Ivory, J. (1995) Experimental and Numerical Simulations of a Novel Top Down In-Situ Combustion Process. International Heavy Oil Symposium, Calgary, AB, Jun. 19-21. |
Coates, R., "Revisiting Top Down In-Situ Combustion-An Alternative Bitumen Recovery Process", presented at Canadian Heavy Oil Association Slugging It Out Conference, Calgary, Alberta, Apr. 10, 2006. |
Galas, C.M.F., Ejiogu, G.C. and Donnelly, J.K. (1991) Fluid and Heat Movements during In-Situ Combustion in a Channelled Reservoir. JCPT May/Jun. 30(3). |
Greaves, M. and Al-Honi, M. (2000) Three-Dimensional Studies of In-Situ Combustion Horizontal Wells Process with Reservoir Heterogeneities. JCPT 39(10)25-32. |
Greaves, M. and Al-Shamali, O. (1996) In Situ Combustion (ISC) Process Using Horizontal Wells, JCPT 35(4) 49-55. |
Greaves, M. and Mahgoub, O. (1996) 3D Physical Model Studies of Air Injection in a Light Oil Reservoir Using Horizontal Wells, International Conference on Horizontal Well Technology, Calgary, AB Nov. 18-20. |
Greaves, M. and Saghr, A.M. (1998) Sleeving-back of Horizontal Wells to Control Downstream Oil Saturations and Improved Oil Recovery, SPE International Conference on Horizontal Well Technology, Calgary, AB Nov. 1-4. |
Greaves, M., and Xia, T.X (2004) Downhole Catalytic Process for Upgrading Heavy Oil: Produced Oil Properties and Composition. JCPT, 43(9)25-30. |
Greaves, M., and Xia, T.X. (2000) Simulation Studies of THAI Process, CIPC Jun. 4-8. |
Greaves, M., Saghr, A.M., Xia, T.X., Turta, A.T. and Ayasse, C. (2001) THAI-New Air Injection Technology for Heavy Oil Recovery and In Situ Upgrading. JCPT 40(3) 38-47. |
Greaves, M., Tuwil, A.A., Bagci, A.S. (1993) Horizontal Producer Wells in Situ Combustion (ISC) Processes, JCPT, Apr. 32(4) 58-67. |
Greaves, M., Wilson, A., Al-Honi, M. and Lockett, A.D.(1996) Improved Recovery of Light/Medium Heavy Oils in Heterogenous Reservoirs Using Air Injection/Insitu Combustion (ISC). SPE 35693, Western Regional Meeting, Anchorage, Alaska May 22-24. |
Greaves, M., Xia, T.X. and Ayasse, C. (2005) Underground Upgrading of Heavy Oil Using THAI-"Toe-to-Heel Air Injection", SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium, Calgary, AB, Nov. 1-3. |
Greaves, M., Xia, T.X., Imbus, S. and Nero, V. (2004) THAI-CAPRI Process: Tracing Downhole Upgrading of Heavy Oil. CIPC Jun. 8-10. |
Hallam, R.J. and Donnelly, J.K. (1993) Pressure-Up Blowdown Combustion: A Channeled Reservoir Process. SPE Advanced Technology Series 1(1) 153-158. |
Herron, E., Hunter, "Commercial Application of In Situ Upgrading of Heavy Oil" Petroleum Equities Inc., Dec. 2003. |
Ivory, J. et al. "Development of a Top-Down Combustion Process", AOSTRA Conference "Oil Sands-Our Petroleum Future" Edmonton, Alberta, Apr. 4-7, 1993. |
Lau, E.C., Good, W.K., Kanakia, V. (1995) COSH Performance and Economical Predictions for Six Field Types in Western Canada. International Heavy Oil Symposium, Calgary, AB, Jun. 19-21. |
Miller, K.A. et al., (2003) Air Injection Recovery of Cold-Produced Heavy Oil Reservoirs, (International Energy Agency's 24th Annual Workshop and Symposium on Enchanced Oil Recovery, Sep. 7-10, 2003, Regina, Saskatchewan, Canada). |
Miller, K.A., Moore, R.G., Ursenbach, M.G., Laureshen, C.J. and Mehta, S.A. (2001) Air Injection Recovery of Cold-Produced Heavy Oil Reservoirs. CIPC, Calgary, Jun. 12-14. |
Miller, K.A., Moore, R.G., Ursenbach, M.G., Laureshen, C.J. and Mehta, S.A., Proposed Air Injection Recovery of Cold-Produced Heavy Oil Reservoirs, JCPT, Mar. 2002, 41(3), 40-49. |
Moore, R.G., Belgrave, J.D.M.,Ursenbach, M.G., Laureshen, C.J., Mehta, S.A., Gomez, P.A. and JHA, K.N. (1999) In Situ Combustion Performance in Steam Flooded Heavy Oil Cores. JCPT, 38(13). |
Mostafavi, S.V., Kharrat, R. and Razzaghi, S. (2007) Feasibility Study of In-Situ Combustion in a Carbonate Reservoir. 15th SPE Middle East Oil and Gas Show and Conference, Kingdom of Bahrain, Mar. 11-14. |
Nzekwu, B.I., Hallam, R.J., and Williams G.J.J. (1990) Interpretation of Temperature Observation From a Cyclic-Steam/In-Situ-Combustion Project. SPE Reservoir Engineering, May, 163-169. |
Razzaghi, S., Kharrat, R., Price, D., Vossoughi and Rashttchian, D. (2005) Feasibility Study of Autoignition Process in Heavy-Oil Reservoirs. SPE International Thermal Operation and Heavy Oil Symposium, Calgary, AB Nov 1-3. |
Stokka, S., Oesthus, A. and Fangeul, J. (2005) Evaluation of Air Injection as an IOR Method for the Giant Ekofisk Chalk Field. SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, Dec. 5-6. |
Tabasinejad, F., Karrat, R. and Vossoughi, S. (2006) Feasibility Study of In-Situ Combustion in Naturally Fractured Heavy Oil Reservoirs. First International Oil Conference and Exhibition in Mexico, Cancun, Aug. 31-Sep. 2. |
Thorton, B., Hassan, D. and Eubank, J. (1996) Horizontal Well Cyclic Combustion, Wabasca Air Injection Pilot. JCPT, 35(9) 40-44. |
Tsang, P.W. (1989) Rationale for Low Injection Rates and Pressure Cycles for Firefloods in Heavy Oil Reservoirs. JCPT, Jan-Feb 28(1), 33-39. |
Turta, A.T. and Singhal, A.K. (1999) Feasibility of Air Injection Based Processes for Williston Basin Reservoirs. International Williston Basin Horizontal Well Workshop, Regina, SK, Apr. 25-27. |
Turta, A.T., Ayasse, C. Najman, J., Fisher, D. and Singhal, A. (2002) Laboratory Investigation of Gravity-Stable Waterflooding Using Toe-to-Heal displacement: Part I: Hele Shaw Model Results. SPE 78988, International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, Nov. 4-7. |
Turta, A.T., Chattopadhyay, S.K., Bhattacharya, R.N., Conrachi, A. and Hanson, W. (2005) Current Status of the Commercial In Situ Combustion (ISC) Projects and New Approaches to Apply ISC. CIPC, Jun. 7-9. |
Xia, T.X. and Greaves, M. (2002) Injection Well-Producer Well Combinations in THAI "Toe-to-Heel Air Injection". SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, Apr. 13-17. |
Xia, T.X., Greaves, M. and Turta, A. (2005) Main mechanism for Stability of THAI-Toe-to-Heel Air Injection. JCPT (44)1. |
Xia, T.X., Greaves, M. and Turta, A.T. (2002) Upgrading Athabasca Tar Sand Using Toe-to-Heel Injection. JCPT 41(8) 51-57. |
Xia, T.X., Greaves, M., Turta, A.T. and Ayasse, C. (2003) THAI-A 'Short Distance Displacement' In Situ Combustion Process for the Recovery and Upgrading of Heavy Oil., Trans IChemE, vol. 81 Part A March. |
Cited By (11)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20090044940A1 (en) * | 2006-02-15 | 2009-02-19 | Pfefferle William C | Method for CAGD recovery of heavy oil |
US9328592B2 (en) | 2011-07-13 | 2016-05-03 | Nexen Energy Ulc | Steam anti-coning/cresting technology ( SACT) remediation process |
US20170002638A1 (en) * | 2011-07-13 | 2017-01-05 | Nexen Energy Ulc | Use of steam assisted gravity drainage with oxygen ("sagdox") in the recovery of bitumen in thin pay zones |
US9803456B2 (en) | 2011-07-13 | 2017-10-31 | Nexen Energy Ulc | SAGDOX geometry for impaired bitumen reservoirs |
US9828841B2 (en) | 2011-07-13 | 2017-11-28 | Nexen Energy Ulc | Sagdox geometry |
US9163491B2 (en) | 2011-10-21 | 2015-10-20 | Nexen Energy Ulc | Steam assisted gravity drainage processes with the addition of oxygen |
US9644468B2 (en) | 2011-10-21 | 2017-05-09 | Nexen Energy Ulc | Steam assisted gravity drainage processes with the addition of oxygen |
US9562424B2 (en) | 2013-11-22 | 2017-02-07 | Cenovus Energy Inc. | Waste heat recovery from depleted reservoir |
CN105545274A (en) * | 2015-12-09 | 2016-05-04 | 中国石油天然气股份有限公司 | Well pattern and method for improving fire flooding effect of thick-layer heavy oil reservoir |
US20180216450A1 (en) * | 2016-08-25 | 2018-08-02 | Conocophillips Company | Well configuration for coinjection |
US11156072B2 (en) * | 2016-08-25 | 2021-10-26 | Conocophillips Company | Well configuration for coinjection |
Also Published As
Publication number | Publication date |
---|---|
US20090188667A1 (en) | 2009-07-30 |
CA2650130C (en) | 2012-03-13 |
CA2650130A1 (en) | 2009-07-30 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US7740062B2 (en) | System and method for the recovery of hydrocarbons by in-situ combustion | |
US20210277757A1 (en) | Pressure assisted oil recovery | |
CA2975611C (en) | Stimulation of light tight shale oil formations | |
CA2569676C (en) | Oilfield enhanced in situ combustion process | |
US7422063B2 (en) | Hydrocarbon recovery from subterranean formations | |
CA2643739C (en) | Diluent-enhanced in-situ combustion hydrocarbon recovery process | |
CA2815737C (en) | Steam assisted gravity drainage with added oxygen geometry for impaired bitumen reservoirs | |
CA2827655C (en) | In situ combustion following sagd | |
Tamer et al. | Impact of different sagd well configurations (dover sagd phase b case study) | |
WO2011071588A1 (en) | Method of controlling solvent injection to aid recovery of hydrocarbons from an underground reservoir | |
Turta | In situ combustion | |
US9328592B2 (en) | Steam anti-coning/cresting technology ( SACT) remediation process | |
Yuan et al. | Application of Geomechanics in Heavy Oil Production-Advanced Canadian Experience | |
RU2581071C1 (en) | Method for development of hydrocarbon fluid deposits | |
Gadelle | In-situ combustion pilot basic design and laboratory experiments | |
Tamer et al. | Impact of well configuration on performance of Steam-Based gravity drainage processes | |
US20230147327A1 (en) | Optimizing steam and solvent injection timing in oil production | |
Bagci et al. | Recovery Performance of Steam-Alternating-Solvent (SAS) Process in Fractured Reservoirs | |
Fatemi et al. | 3D simulation study on the performance of toe-to-heel air injection (THAI) process in fractured carbonate systems | |
Bagcı et al. | Case histories for heavy oil recovery in naturally fractured carbonate reservoirs in the Middle East | |
EP2025862A1 (en) | Method for enhancing recovery of heavy crude oil by in-situ combustion in the presence of strong aquifers |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: ALBERTA RESEARCH COUNCIL INC., CANADA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:LIM, GIT;IVORY, JOHN;COATES, ROY;REEL/FRAME:020797/0050;SIGNING DATES FROM 20080222 TO 20080325 Owner name: ALBERTA RESEARCH COUNCIL INC.,CANADA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:LIM, GIT;IVORY, JOHN;COATES, ROY;SIGNING DATES FROM 20080222 TO 20080325;REEL/FRAME:020797/0050 |
|
STCF | Information on status: patent grant |
Free format text: PATENTED CASE |
|
AS | Assignment |
Owner name: ALBERTA INNOVATES - TECHNOLOGY FUTURES, CANADA Free format text: NUNC PRO TUNC ASSIGNMENT;ASSIGNOR:ALBERTA RESEARCH COUNCIL INC.;REEL/FRAME:025105/0843 Effective date: 20091217 |
|
FPAY | Fee payment |
Year of fee payment: 4 |
|
AS | Assignment |
Owner name: ALBERTA INNOVATES, CANADA Free format text: CHANGE OF NAME;ASSIGNOR:ALBERTA INNOVATES - TECHNOLOGY FUTURE;REEL/FRAME:043315/0074 Effective date: 20161101 |
|
AS | Assignment |
Owner name: ALBERTA INNOVATES, CANADA Free format text: CORRECTIVE ASSIGNMENT TO CORRECT THE ASSIGNEE NAME PREVIOUSLY RECORDED ON REEL 043315 FRAME 0074. ASSIGNOR(S) HEREBY CONFIRMS THE CHANGE OF NAME;ASSIGNOR:ALBERTA INNOVATES - TECHNOLOGY FUTURES;REEL/FRAME:043790/0646 Effective date: 20161101 |
|
MAFP | Maintenance fee payment |
Free format text: PAYMENT OF MAINTENANCE FEE, 8TH YEAR, LARGE ENTITY (ORIGINAL EVENT CODE: M1552) Year of fee payment: 8 |
|
AS | Assignment |
Owner name: INNOTECH ALBERTA INC., ALBERTA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:ALBERTA INNOVATES;REEL/FRAME:044935/0144 Effective date: 20161101 |
|
MAFP | Maintenance fee payment |
Free format text: PAYMENT OF MAINTENANCE FEE, 12TH YEAR, LARGE ENTITY (ORIGINAL EVENT CODE: M1553); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY Year of fee payment: 12 |